Well stimulation compositions

ABSTRACT

A well service fluid composition comprises a fracturing fluid and a gas hydrate inhibitor. Preferably, the gas hydrate inhibitor does not affect the function of the fracturing fluid and is present in an amount sufficient to control and/or minimize the formation of gas hydrates. The well service fluid composition is useful in hydraulic fracturing in which the composition is injected into a subterranean formation under sufficient pressure to initiate and propagate a fracture in the formation. The fracturing fluid may be subsequently recovered when the fracturing operation is completed.

This application is a continuation of U.S. patent application Ser. No.09/885,412 filed May 15, 2001 now U.S. Pat. No. 6,756,345, which claimspriority to a prior U.S. Provisional patent application, Ser. No.60/204,153, filed May 15, 2000, entitled Well Stimulation Compositionand Method.

FEDERALLY SPONSORED RESEARCH

Not applicable.

REFERENCE TO NICROFICHE APPENDIX

Not applicable.

FIELD OF THE INVENTION

The embodiments of the invention relates to compositions and methods foruse in well service and, more particularly, to fracturing fluids and amethod of using same.

BACKGROUND OF THE INVENTION

A common practice in the recovery of oil and/or gas from subterraneanformations is to treat the formations to increase their grosspermeability or conductivity by procedures that are identified generallyas fracturing processes. For example, it is a conventional practice tohydraulically fracture an oil or gas well in order to produce andpropagate one or more cracks or “fractures” in the surrounding formationby mechanical breakdown of the formation.

Hydraulic fracturing typically is accomplished by injecting a hydraulicfracturing fluid into the well and imposing sufficient pressure on thefracturing fluid to cause the formation to break down with the attendantproduction of one or more fractures. The fracturing fluid is usually agel, an emulsion, or a form having a proppant such as sand or otherparticulate material suspended therein. The proppant is deposited intothe fracture and functions to hold the fracture open after the pressureis released and the fracturing fluid is recovered from the well.

After the fracturing fluid has been pumped into the formation andfracturing of the formation has been achieved, it is desirable to removethe fluid from the formation to allow hydrocarbon production through thenew fractures. Generally, the removal of the fracturing fluid, which ishighly viscous, is realized by “breaking” the gel, emulsion, etc., i.e.,by converting the fracturing fluid into a low viscosity fluid.

As oil and gas exploration and production moves into progressivelydeeper offshore waters, greater challenges are being presented. Forexample, it is known that gas hydrates pose particular problems withrespect to the producing, transporting, and processing of natural gasand petroleum fluids. These gas hydrates, known as clathrate hydrates,are crystalline compounds that form when water forms a cage-likestructure around gas molecules, particularly gaseous molecules. Typicalgas hydrates formed in petroleum environments are composed of water andone or more gas molecules such as methane, ethane, propane, isobutane,normal butane, nitrogen, carbon dioxide, hydrogen sulfide, etc.

While gas hydrate formation may pose a significant problem duringproduction from a well, it may also pose a problem in a fracturingoperation. As noted above, once the fracturing operation has beencompleted, the fracturing liquid has to be recovered or unloaded beforethe well commences producing hydrocarbons. In the unloading process, thefracturing fluid is frequently saturated with one or more of the gasesmentioned above, which undergo decompression, resulting Joule-Thompsoncooling of the fracturing fluid. Accordingly, when the fracturing fluidis water-based, gas hydrates may form at certain well depths, pluggingthe well and interfering with the process of bringing the well onstream.Therefore, there is a need for a well service composition and method forcontrolling or minimizing the formation of gas hydrates.

SUMMARY OF THE INVENTION

The above need is met by embodiments of the invention in one or more ofthe following aspects. In one aspect, the invention relates to a wellservice composition comprising a fracturing fluid and a gas hydratecontroller. The gas hydrate controller is in an amount effective tocontrol the formation of gas hydrates. The gas hydrate controller mayinclude, but is not limited to, polyglycolpolyamines used alone or incombination with one or more polymers capable of controlling orminimizing the formation of gas hydrates. Additional aspects of theinvention relate to methods of making and using the composition.Characteristics and advantages provided by embodiments of the inventionbecome apparent with the following description.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of the testing apparatus used.

DESCRIPTION OF EMBODIMENTS OF THE INVENTION

Embodiments of the invetion provide a well service composition andmethods of making and using the composition. The well servicecomposition comprises a fracturing fluid and a gas hydrate inhibitor.Preferably, the gas hydrate inhibitor should be present in an effectiveamount to control and/or minimize the formation of gas hydrates.

The term “fracturing fluid” is intended to encompass any water-basedfluid that can be used in oil and gas reservoirs for stimulation, i.e.,to enhance oil and/or gas from the reservoir. Fracturing fluids usefulin embodiments of the invention comprises at least a carrier fluid,usually an aqueous liquid, and a viscosifying polymer.

Suitable water-containing fracturing fluids of embodiments of theinvention comprises of water-soluable or dispersible polymers orpolymeric-type materials, such as surfactants that form micelles andsignificantly increase the viscosity of the carrier fluid, includingpolysaccharides such as galactomannan gums, glucomannan gums, and theirderivatives. Solvatable galactomannan and glucomannan gums are naturallyoccurring. The galactomannan gums can also be reacted with hydrophilicconstituents and thereby produce derivatized polymers useful inembodiments of the invention. Solvatable polysaccharides with molecularweights of greater than about 200,000 are preferred. More preferredsolvatable polysaccharides have molecular weights in the range of fromabout 200,000 to about 3,000,000. Non-limiting examples of suchpolysaccharides include, but are not limited to, guar gum, locust beangum, karaya gum, xanthan gum, and guar derivatives such as carboxymethylguar, carboxyethyl guar, hydroxypropyl guar, hydroxyethyl guar, andcarboxymethylhydroxypropyl guar. Cellulose derivatives such ashydroxypropyl cellulose, carboxymethyl cellulose,carboxymethylhydroxypropyl cellulose, hydroxyethyl cellulose andcarboxymethylhydroxyethyl cellulose are also useful in embodiments ofthe invention. Additional solvatable polymers may also include sulfatedor sulfonated guars, cationic guars derivatized with agents such as3-chloro-2-hydroxypropyl trimethylammonium chloride, and syntheticpolymers with anionic groups, such as polyvinyl acetate,polyacrylamides, poly-2-amino-2-methyl propane sulfonic acid, andvarious other synthetic polymers and copolymers. Moreover, U.S. Pat. No.5,566,760 discloses a class of hydrophobically modified polymers for usein fracturing fluids. These hydrophobically modified polymers may beused in embodiments of the invention with or without modification. Thedisclosure of the patent is incorporated by reference herein in itsentirety. Other suitable polymers include those known or unknown in theart.

The polymer may be present in the fluid in concentrations ranging fromabout 0.05% to about 5.0% by weight of the aqueous fluid. A preferredrange for the solvatable polymer is about 0.20% to about 0.80% byweight. In some embodiments, about 20 lbs. or less of a polymer is mixedwith 1000 gal. of an aqueous fluid. For example, about 5, 10, or 15 lbs.of a polymer may be mixed with 1000 gal. of an aqueous fluid. Undercertain circumstances, it is more advantageous to have reduced polymerloading (i.e., a polymer concentration of 0.14 wt. % or less or 20 pptor less). This is because less damage would occur to a formation if areduced level of polymers is used in a fracturing fluid. An additionalbenefit of reduced polymer loading may be increased fractureconductivity. Although it may be beneficial to employ polymers at areduced level, a fracturing fluid may be formulated at a higher polymerlevel. For example, about 20 lbs. or higher of a polymer may be mixedwith 1000 gal. of an aqueous fluid. Specifically, about 25 lbs., 30lbs., 35 lbs., 40 lbs., 45 lbs., 50 lbs., 55 lbs., or 60 lbs. of apolymer may be mixed with 1000 gal. of an aqueous fluid. In someembodiments, about 65 lbs. or more of a polymer may be mixed with 1000gal. of an aqueous fluid

As disclosed in Reservoir Stimulation, 2^(nd) Edition (Prentice Hall),Chapter 4: “Fracturing Fluid Chemistry,” Janet Gulbis, and Chapter 7:“Fracturing Fluids and Additives,” John W. Ely, incorporated herein byreference for all purposes, a number of additives, in addition to thecarrier liquid, viscosifying agent, and proppant, can be incorporatedinto the fracturing fluids of embodiments of the invention. For example,additives such as crosslinking agents, biocides, breakers, buffers,surfactants and non-emulsifiers, fluorocarbon surfactants, claystabilizers, fluid loss additives, foamers, friction reducers,temperature stabilizers, diverting agents, etc., can be incorporatedinto the fracturing fluids of embodiments of the invention.

A suitable crosslinking agent can be any compound that increases theviscosity of the fluid by chemical crosslinking, physical crosslinking,or any other mechanisms. For example, the gellation of a solvatablepolymer can be achieved by crosslinking the polymer with metal ionsincluding aluminum, antimony, zirconium, and titanium containingcompounds. One class of suitable crosslinking agents is organotitanates.Another class of suitable crosslinking agents is borates as described,for example, in U.S. Pat. No. 4,514,309, or organoborates as described,for example, in U.S. Pat. No. 5,145,590, which are incorporated byreference herein in their entirety. The selection of an appropriatecrosslinking agent depends upon the type of treatment to be performedand the solvatable polymer to be used. The amount of the crosslinkingagent used also depends upon the well conditions and the type oftreatment to be effected, but is generally in the range of from about0.01 to about 1.0 parts by weight of crosslinking agent per 100 parts byweight of the aqueous fluid. In some applications, the aqueous polymersolution is crosslinked immediately upon addition of the crosslinkingagent to form a highly viscous gel. In other applications, the reactionof the crosslinking agent can be retarded so that viscous gel formationdoes not occur until the desired time.

A suitable borate cross-linking agent may be used in any amount toeffect the cross-linking and, thus, to increase the viscosity of afracturing fluid. The concentration of a borate cross-linking agentgenerally is dependent upon factors such as the temperature and theamount of the polymer used in a fracturing fluid. Normally, theconcentration may range from about 5 ppm to about 100 ppm, preferablyfrom about 10 ppm to about 70 ppm. A borate cross-linking agent may beused in any form, such as powder, solution, or granule. Encapsulatedborates may also be used. Encapsulated borate may be prepared byproviding a hydrocarbon-based enclosure member which envelopes abreaking agent. Encapsulation may be accomplished by the methoddescribed in U.S. Pat. No. 4,919,209, which is incorporated by referenceherein in its entirety. A delayed cross-linking system may also be usedin embodiments of the invention. U.S. Pat. No. 5,160,643, No. 5,372,732,and 6,060,436 disclose various delayed borate cross-linking system thatcan be used in embodiments of the invention. The disclosures of thepreceding patents are incorporated by reference in their entiretyherein. Additional suitable borate cross-linking agents are disclosed inthe following U.S. Pat.: No. 4,619,776; U.S. Pat. No. 5,082,579, U.S.Pat. No. 5,145,590, U.S. Pat. No. 5,372,732; U.S. Pat. No. 5,614,475;U.S. Pat. No. 5,681,796; U.S. Pat. No. 6,060,436; and U.S. Pat. No.6,177,385, all of which are (or have been) incorporated by referenceherein in their entirety.

The pH of an aqueous fluid which contains a solvatable polymer can beadjusted if necessary to render the fluid compatible with a crosslinkingagent. Preferably, a pH adjusting material is added to the aqueous fluidafter the addition of the polymer to the aqueous fluid. Typicalmaterials for adjusting the pH are commonly used acids, acid buffers,and mixtures of acids and bases. For example, hydrochloric acid, fumaricacid, sodium bicarbonate, sodium diacetate, potassium carbonate, sodiumhydroxide, potassium hydroxide, and sodium carbonate are typical pHadjusting agents. Acceptable pH values for the fluid may range fromacidic, neutral, to basic, i.e., from about 0.5 to about 14. Preferably,the pH is kept neutral or basic, i.e., from about 7 to about 14, morepreferably between about 8 to about 12. Other pH ranges include, but arenot limited to, between about 9 to about 11, between about 7 to about11, between about 7 to about 12, between about 5 to about 9, betweenabout 3 to about 10 or between about 6 to about 9. It is also possibleto use a fracturing fluid with a pH outside the above ranges. In someembodiments, a fracturing fluid may have an initial pH of less thanabout 7.5, such as about 3.5, about 5, or about 5.5. The pH may then beincreased to above 7.5, such as between about 8.5 to about 11. After thetreatment, the pH may be decreased to less than about 7.5. Therefore, afracturing fluid may be acidic, neutral, or basic, depending on how itis used in well treatments.

The fracturing fluid in accordance with embodiments of the invention mayinclude a breaking agent or a breaker. The term “breaking agent” or“breaker” refers to any chemical that is capable of reducing theviscosity of a gelled fluid. As described above, after a fracturingfluid is formed and pumped into a subterranean formation, it isgenerally desirable to convert the highly viscous gel to a lowerviscosity fluid. This allows the fluid to be easily and effectivelyremoved from the formation and to allow desired material, such as oil orgas, to flow into the well bore. This reduction in viscosity of thetreating fluid is commonly referred to as “breaking”. Consequently, thechemicals used to break the viscosity of the fluid is referred to as abreaking agent or a breaker.

There are various methods available for breaking a fracturing fluid or atreating fluid. Typically, fluids break after the passage of time and/orprolonged exposure to high temperatures. However, it is desirable to beable to predict and control the breaking within relatively narrowlimits. Mild oxidizing agents are useful as breakers when a fluid isused in a relatively high temperature formation, although formationtemperatures of 300° F. or higher will generally break the fluidrelatively quickly without the aid of an oxidizing agent.

Both organic oxidizing agents and inorganic oxidizing agents have beenused as breaking agents. Any breaking agent or breaker, both inorganicand organic, may be used in embodiments of the invention. Examples oforganic breaking agents include, but are not limited to, organicperoxides, and the like.

Examples of inorganic breaking agents include, but are not limited to,persulfates, percarbonates, perborates, peroxides, chlorites,hypochlorites, oxides, perphosphates, permanganates, etc. Specificexamples of inorganic breaking agents include, but are not limited to,ammonium persulfates, alkali metal persulfates, alkali metalpercarbonates, alkali metal perborates, alkaline earth metalpersulfates, alkaline earth metal percarbonates, alkaline earth metalperborates, alkaline earth metal peroxides, alkaline earth metalperphosphates, zinc salts of peroxide, perphosphate, perborate, andpercarbonate, alkali metal chlorites, alkali metal hypochlorites, KBrO₃,KClO₃, KIO₃, sodium persulfate, potassium persulfate, and so on.Additional suitable breaking agents are disclosed in U.S. Pat. No.5,877,127; U.S. Pat. No. 5,649,596; U.S. Pat. No. 5,669,447; U.S. Pat.No. 5,624,886; U.S. Pat. No. 5,106,518; U.S. Pat. No. 6,162,766; andU.S. Pat. No. 5,807,812. The disclosures of all of the preceding patentsare incorporated by reference herein in their entirety.

In addition, enzymatic breakers may also be used in place of or inaddition to a non-enzymatic breaker. Examples of suitable enzymaticbreakers are disclosed, for example, in U.S. Pat. No. 5,806,597 and U.S.Pat. No. 5,067,566, which are incorporated by reference herein in theirentirety. A breaking agent or breaker may be used as is or beencapsulated and activated by a variety of mechanisms including crushingby formation closure or dissolution by formation fluids. Such techniquesare disclosed, for example, in U.S. Pat. No. 4,506,734; U.S. Pat. No.4,741,401; U.S. Pat. No. 5,110,486; and U.S. Pat. No. 3,163,219, whichare incorporated by reference herein in their entirety. In someembodiments, an inorganic breaking agent is selected from alkaline earthmetal or transition metal-based oxidizing agents, such as magnesiumperoxides, zinc peroxides, and calcium peroxides. Other suitablebreakers include the ester compounds disclosed in U.S. ProvisionalPatent Application Ser. No. 60/260,442, filed on Jan. 9, 2001, thedisclosure of which is incorporated by reference herein in its entirety.

As described above, propping agents or proppants may be added to thefracturing fluid, which is typically done prior to the addition of acrosslinking agent. However, proppants may be introduced in any mannerwhich achieves the desired result. Any proppant may be used inembodiments of the invention. Examples of suitable proppants include,but are not limited to, quartz sand grains, glass and ceramic beads,walnut shell fragments, aluminum pellets, nylon pellets, and the like.Proppants are typically used in concentrations between about 1 to 8 lbs.per gallon of a fracturing fluid, although higher or lowerconcentrations may also be used as desired. The fracturing fluid mayalso contain other additives, such as surfactants, corrosion inhibitors,mutual solvents, stabilizers, paraffin inhibitors, tracers to monitorfluid flow back, etc.

The fracturing fluids of used in embodiments of the invention can besingle-phase or multi-phase and, in the latter case, can compriseemulsion fracturing fluids and foam-based fluids.

The well service compositions in accordance with embodiments of theinvention, in addition to containing a fracturing fluid as discussedabove, also contain a gas hydrate controller. The terms “gas hydratecontroller” and “gas hydrate inhibitor” as used herein refer to achemical or composition of matter that retards the formation of gashydrate crystals and/or retards the agglomeration of gas hydratecrystals if they do not form. Preferably, the gas hydrate inhibitor doesnot substantially adversely affect the fracturing fluid and remainsactive after the fracturing fluid has been broken and the fracturingfluid is recovered in the unloading process.

Non-limiting examples of suitable gas hydrate inhibitors include, butare not limited to, compositions such as polymers, includinghomopolymers and copolymers of monomers such asN,N-dialkylaminoethylmethacrylates, N-vinyl-N-alkyl amides, and N-vinyllactams. A generic structure of a N-methyl-N-vinylacetamide(VIMA)/lactam copolymer, also useful in embodiments of the invention, isdepicted as follows:

where n ranges from one to three and the sum of x and y is an averagenumber sufficient to produce an average molecular weight between about1,000 to about 6,000,000.

Compounds belonging to the group of polymers and copolymers of N-acylsubstituted polyalkeneimines, and mixtures thereof, are very effectiveinhibitors of hydrate nucleation, growth, and/or agglomeration(collectively referred to as hydrate formation). This group includespolymers derived from 2-alkyl-2-oxazolines, 2-alkyl-2-oxazines and othercyclic imino ethers. A generic structure for these polymers is depictedas follows:

where R is hydrogen or an alkyl, aryl, alkylaryl, cycloalkyl, orheterocyclic group such that the resultant polymer is substantiallywater soluble, n ranges from one to four and x is an average integersufficient to produce an average molecular weight between about 1,000 toabout 1,000,000.

Other gas hydrate inhibitors include, but are not limited to,polyglycolpolyamines, which are polycondensation products of thereaction of one or more polyamines with one or more, polyoxyalkyleneglycol derivatives. The polyoxyalkylene glycol derivatives may berepresented as follows:

wherein R₁ is a member selected from the group consisting of oxygen,glyceryloxy, lower alkylene dicarboxyloxy and lower aklylene diisocyano;R₂ is a member selected from the group consisting of hydrogen, methyland ethyl; R₄ and R₆ individually are selected from the group consistingof halo-, -hydroxyl-lower alkyl, -epoxy-lower alkyl, and α-sulfato-loweralkyl; and n is an integer from 2 to 35.

The polyamines have the formula:

wherein R₃ is a member selected from the group consisting of hydrogenand methyl and m is an integer from 1 to 3.

The polyoxyakylene glycol derivatives and the polyamines are reacted ina molar ratio of about 1:0.8 to about 1:1.5, preferably about 1:1.05 toabout 1:1.2 at a temperature of from about 75 C to about 160 C toproduce polyglycol polyamines represented by the following structure:R₇R′NCHR″CH₂(OCH₂CHR″)_(n)N(R′)₂wherein R₇ is H, CH₃, or —[R′NCHR″CH₂(OCH₂CHR″)_(n)NR′]_(m)—R′, R′ is Hor CH₃, R″is H OR CH₃, n is 1 to 99 and m is 0 to 99. Additionalsuitable gas hydrate controllers are also disclosed in U.S. Pat. Nos.6,025,302; 5,741,758, 5,460,728, 5,432,292, 5,426,258; 5,491,269,5,351,756, 5,331,105; 5,076,364; 4,973,775; 4,915,176; 4,678,558;4,602,920; 4,597,779; 4,456,067, and references cited therein, all ofwhich are incorporated herein by reference for all purposes. It shouldbe understood that a mixture of various gas hydrate inhibitors can beemployed. Thus, polyglycolpolyamines can be mixed with certain polymericinhibitors to provide a system that not only retards the formation ofgas hydrate crystals but retards the clustering or agglomeration of suchcrystals should they form.

The following U.S. patents further disclose various polymers forretarding the formation of gas hydrate crystals and/or retarding theagglomeration of gas hydrate crystals if they are already formed whichmay be employed in embodiments of the invention with or withoutmodifications: U.S. Pat Nos. 6,117,929; 5,880,319; 5,874,660; 5,639,925;5,491,269 and 3,987,162. All of the preceding patents are incorporatedby reference herein in their entirety.

In formulating a well service composition, the gas hydrate inhibitor canbe added to the fracturing fluid prior to the fluid being pumped intothe formation. Alternatively, it is possible to inject the gas hydrateinhibitor into a formation into which the fracturing has already beenintroduced.

The amount of gas hydrate inhibitor present in a well servicecomposition can vary over a wide range, depending on numerous factors,such as the nature of the fracturing fluid, the water content of thefracturing fluid, temperature and pressure conditions in the well, andother such factors. Thus, knowing such parameters, an effective amountof the gas hydrate inhibitor or controller can be easily determined andadded to a given fracturing fluid. Generally, the gas hydrate inhibitormay be present in the composition in an amount of from about 0.01 toabout 5% by weight, preferably from about 0.05 to about 1% by weight ofthe water present in composition, more particularly in an amount of fromabout 0.03 to about 0.75% by weight of the water present in thecomposition.

As described above, a fracturing fluid may include a number ofcomponents. Table I below exemplifies some acceptable compositionalranges for the fluid. It should be understood that compositions outsidethe indicated ranges are also within the scope of the invention.

TABLE I Exemplary Composition Ranges* Suitable Other Suitable StillOther Suitable Component Range (wt %) Range (wt %) Range (wt %) Polymer0.1–5.0 0.14–1.0  0.2–0.8 Crosslinking 0.001–5.0  0.005–2.0  0.01–1.0 Agent Breaking Agent 0.001–1.0  0.005–0.5  0.01–0.12 Proppant  3–300 6–180 12–96 pH Buffer  2–14  3–13  8–12 Gas Hydrate 0.01–5   0.05–1  0.03–0.75 Inhibitor *note: each weight percentage is based on the totalweight of the solvent (e.g., water).

The fracturing fluid in accordance with embodiments of the invention hasmany useful applications. For example, it may be used in hydraulicfracturing, gravel packing operations, water blocking, temporary plugsfor purposes of wellbore isolation and/or fluid loss control, and otherwell completion operations. One application of the fracturing fluid isin hydraulic fracturing. In use, the well service composition, asdescribed above, is injected into a subterranean formation to befractured. Sufficient pressure is applied on the formation for asufficient period of time to fracture the formation and propagate thefracture. Following fracturing, and if necessary, the fracturing fluidis broken with a suitable breaker, following which the pressure on theformation is released, the fracturing fluid is then recovered.

Accordingly, embodiments of the invention provide a method ofstimulating a subterranean formation. The method includes: (a)formulating a fracturing fluid comprising an aqueous fluid, awater-soluble polymer, and a gas hydrate controller capable ofcontrolling or minimizing the formation of gas hydrates; and (b)injecting the fracturing fluid into a bore hole to contact at least aportion of the formation by the fracturing fluid under a sufficientpressure to fracture the formation. Under some circumstances, theinitial viscosity of the fracturing fluid should be maintained above atleast 200 cP at 40 sec⁻¹ during injection and, afterwards, should bereduced to less than 200 cP at 40 sec⁻¹. After the viscosity of thefracturing fluid is lowered to an acceptable level, at least a portionof the fracturing fluid is removed from the formation. During thefracturing process, a proppant can be injected into the formationsimultaneously with the fracturing fluid. Preferably, the fracturingfluid has a pH around or above about 7, more preferably in the range ofabout 8 to about 12.

It should be understood that the above-described method is only one wayto carry out embodiments of the invention. Other suitably methods aredescribed in U.S. Pat. Nos. 6,135,205; 6,123,394; 6,016,871; 5,755,286;5,722,490; 5,711,396; 5,551,516; 5,497,831; 5,488,083; 5,482,116;5,472,049; 5,411,091; 5,402,846; 5,392,195; 5,363,919; 5,228,510;5,074,359; 5,024,276; 5,005,645; 4,938,286; 4,926,940; 4,892,147;4,869,322; 4,852,650; 4,848,468; 4,846,277; 4,830,106; 4,817,717;4,779,680; 4,479,041; 4,739,834; 4,724,905; 4,718,490; 4,714,115;4,705,113; 4,660,643; 4,657,081; 4,623,021; 4,549,608; 4,541,935;4,378,845; 4,067,389; 4,007,792; 3,965,982; and 3,933,205. All of thepreceding patents are incorporated by reference herein in theirentirety.

The following examples are presented to illustrate an embodiments of theinvention. None of the examples is intended, nor should they beconstrued, to limit the invention as otherwise described and claimedherein. All numerical values are approximate. Numerical ranges, ifgiven, are merely exemplary. Embodiments outside the given numericalranges may nevertheless fall within the scope of the invention asclaimed.

Testing Procedure

A gas hydrate simulation test was applied for testing the efficiency ofgas hydrate inhibitors. The test apparatus is shown in FIG. 1 andcomprises a length of coiled tubing 10, a cooling bath 20, and aplurality of fluid reservoirs 30. The coiled tubing 10 consisted of a 20m long 1 mm ID piece of stainless steel tubing. The coiled tubing 10 wasimmersed into the cooling bath 20. The cooling bath 20 was filled withan ethylene glycol/water mixture. An end section 40 of the coiled tubing10 was placed outside the cooling bath 20 and after a pressuregauge/recorder 50. The end section 40 consisted of a short (1 m) 0.05 mmID stainless steel tubing which emptied into the fluid reservoir 30 b.This end section 40 reduced the fluid flow to 2.4 ml/h at a constantfeeding pressure 0.1 atm. In each experiment the test solution waspumped from the fluid reservoir 30 a through the simulated pipeline(coiled tubing 10 and end section 40) at preset temperatures of −13 to−20° C. The fracturing fluid was formulated in water as follows:

3.5% (wt/vol) sodium chloride

0.48% (wt/vol) guar gum

0.20% (vol) 45% aq. Potassium carbonate

0.50% (vol) gas hydrate inhibitor

hydrochloric acid to adjust pH to 10

0.20% (vol) boron additive defined in U.S. Pat. No. 5,082,579

0.10% (vol) concentrated liquid enzyme, galactomanose (gel breaker)

Each fracturing fluid described above was left for 24 hours at roomtemperature in the fluid reservoir 30 a to allow the enzyme breaker todigest the guar polymer and to convert the highly viscous gel tonon-viscous fluid. The broken fracturing gel (can be also calledfracturing return fluid) was filtered through a filter 60. The filter 60was a 10 micron filter. The filtration step was necessary to remove anysolid polymer residues from the fluid. The solids would interfere withthe testing process. The test fluid was prepared by addingtetrahydrofuran (THF) (20%) to the broken and filtered fracturing gel.It has been published and proved that the THF/salt water solutionstimulates gas/water systems without the necessity of running tests athigh pressures with highly flammable gas. (See Couch, D. W. Davidson,Can J. Chem., 49, 2961 (1971)).

The test fluid was tested in the coiled tubing 10. The volume of fluidinside the coiled tubing 10 was 60 ml and allowed a 25 hr fluidresidence time inside the cooling bath 20 at a flow volume of 0.04ml/min. The flow volume through the simulated gas pipeline was monitoredand recorded with time. The filter 60 located at the coiled tubing 10intake assured that a flow stop did not occur from plugging the linewith impurities, and was caused only by blockage with hydrate crystalsbeing formed in the simulated gas line cooled inside the cooling bath20. The coiled tubing 10 was warmed up to 60° C. and washed with waterand the next test fluid after completion of each test.

In each experiment the fluid flow time was measured from the beginningof flow until the stoppage of flow as a result of complete coilplugging. Due to the test variability the freeze times shown in Table IIare the average of five runs each. Longest runs at lowest temperaturesindicate best hydrate protection. The results are shown in Table IIbelow.

TABLE II Flow Times of Broken Borate Fracturing Fluid with Various GasHydrate Inhibitors through Simulated Test Pipeline at VariousTemperatures Flow Time Hours @ Test Temperature, ° C. Sample −13 −14−15.5 −16 −16.25 −17.25 −17.5 −18.5 −19.25 −19.5 1¹ >24 h 24 h 13 h   10h    8 h   1.5 h   1 h 2² >24 h   16 h     4 h 2.3 h 3³ 24 h >24 h >24 h >24 h 3.6 h   1 h 0.4 h 4⁴ >24 h  >24 h  20 h 1.5 h 0.5 h 0.25 h ¹Nogas hydrate inhibitor present. ²Gas hydrate inhibitor was 0.5% (wt/vol)poly[oxy(methyl 1,2-ethanediyl)],alpha-(2-aminomethylethyl)omega-(2-aminoethylethoxy). ³Gas hydrateinhibitor was 0.25% (wt/vol) of polyvinylcaprolactam and 0.25% (wt/vol)of quaternized polyglycolpolyamine gas hydrate inhibitor as defined inU.S. Pat. No. 6,025,302. ⁴Gas hydrate inhibitor was 0.25% (wt/vol) ofpolyvinylcarprolactam and 0.25% (wt/vol) of polyglycoldiamine describedin Footnote 3.

As the results in Table II show, there is an improvement of hydrateinhibition in fluids treated with gas hydrate inhibitors. Particularly,fluids treated with mixed gas hydrate inhibitors likepolymer/polyetherpolyamine or polymer/quaternized polyetherpolyaminedisplayed the best performance.

As demonstrated above, embodiments of the invention provide a wellservice composition and a method of using the well service composition.The well service composition in accordance with some embodiments of theinvention controls or minimizes the formation of gas hydrates the use ofa gas hydrate inhibitor. When gas hydrate inhibitors are used, aproduction well can be brought onstream with no plugging. Additionalcharacteristics and advantages provided by embodiments of the inventionare apparent to those skilled in the art.

While the invention has described with respect to a limited number ofembodiments, these embodiments are not intended to limit the scope ofthe invention as otherwise described and claimed herein. Variations andmodifications from the described embodiments exist. For example, whilepolyglycolpolyamines are exemplified as suitable gas hydrate inhibitors,other types of inhibitors may also be used. Although a boratecross-linking agent is exemplified as a preferred cross-linking agent,this does not preclude the use of other types of cross-linking agents,such as antimony-based cross-linking agents. Similarly, although guarpolymers are exemplified as preferred polymers in formulating afracturing fluid, this does not preclude the use of other types ofpolymers, both synthetic and natural. Generally, it is more economicalto employ an aqueous fluid to form a fracturing fluid, this does notpreclude a non-aqueous fluid being formulated and used in accordancewith embodiments of the invention. In cases where water is no longer thepredominant component of a fracturing fluid, a hydratable orwater-soluble polymer may not be necessary. Instead, other polymers suchas water insoluble polymers, may be used. In describing the method ofmaking and using the fracturing fluid, various steps are disclosed.These steps may be practiced in any order or sequence unless otherwisespecified. Moreover, one or more steps may be combined into one singlestep. Conversely, one step may be practiced in two or more sub-steps.Whenever a number is disclosed herein, it should be interpreted to mean“about” or “approximate,” regardless of whether these terms are used indescribing the number. The appended claims intend to cover all suchvariations and modifications as falling within the scope of theinvention.

1. A well stimulation composition comprising a fracturing fluidcomprising an aqueous fluid, a guar polymer or a derivative thereof, across-linking agent capable of increasing the viscosity of thefracturing fluid by cross-linking the polymer in the aqueous fluid, anda breaking agent; and a gas hydrate controller selected from the groupconsisting of homopolymers or copolymers ofN,N-dialkylamineoethylmethacrylates, homopolymers or copolymers ofN-vinyl-N-alkyl amides, homopolymers or copolymers of N-vinyl lactams,homopolymers or copolymers of N-methyl-N-vinylacetamide/lactams,homopolymers or copolymers of N-acyl substituted polyalkeneimines, andmixtures thereof, wherein the gas hydrate controller is present in thecomposition in an amount effective to control the formation of gashydrates.
 2. The composition of claim 1, wherein the aqueous fluid ismixed with the polymer on a ratio of about 20 pounds or less of thepolymer for 1,000 gallons of the aqueous fluid.
 3. The composition ofclaim 1, wherein the aqueous fluid is mixed with the polymer on a ratioof about 20 pounds or more of the polymer for 1,000 gallons of theaqueous fluid.
 4. The composition of claim 1, wherein the polymer isguar, carboxymethyl guar, carboxyethyl guar, hydroxypropyl guar,hydroxyethyl guar, carboxymethylhydroxypropyl guar, salts thereof, ormixtures thereof.
 5. The composition of claim 1, wherein thecross-linking agent is boric acid, organoborate, boric oxide, alkalimetal borate, alkaline earth metal borate, or a mixture thereof.
 6. Thecomposition of claim 1, wherein the fracturing fluid further comprises aproppant.
 7. The composition of claim 1, wherein the fracturing fluidfurther comprises a clay stabilizer.
 8. The composition of claim 7,wherein the clay stabilizer is KCl or a quartemary ammonium salt.
 9. Thecomposition of claim 1, wherein the fracturing fluid further comprises apH buffering agent.
 10. The composition of claim 1, wherein the gashydrate controller is from about 0.01 to about 5% by weight of the waterin the composition.
 11. The composition of claim 1, wherein the gashydrate controller is from about 0.05 to about 1% by weight of the waterin the composition.
 12. The composition of claim 1, wherein the gashydrate controller is from about 0.03 to about 0.75% by weight of thewater present in the composition.
 13. A method of fracturing asubterranean formation comprising: obtaining a well service compositioncomprising a fracturing fluid comprising an aqueous fluid, a guarpolymer or a derivative thereof, and a cross-linking agent capable ofincreasing the viscosity of the fracturing fluid by cross-linking thepolymer in the aqueous fluid; and a gas hydrate controller selected fromthe group consisting of homopolymers or copolymers ofN,N-dialkylamineoethylmethacrylates, homopolymers or copolymers ofN-vinyl-N-alkyl amides, homopolymers or copolymers of N-vinyl lactams,homopolymers or copolymers of N-methyl-N-vinylacetamide/lactams,homopolymers or copolymers of N-acyl substituted polyalkeneimines, andmixtures thereof, said gas hydrate controller being present in saidcomposition in an amount effective to control the formation of gashydrates; and injecting the well service composition into a borehole tocontact at least a portion of the formation by the fracturing fluidunder a sufficient pressure to fracture the formation.
 14. The method ofclaim 13, wherein the gas hydrate controller is from about 0.01 to about5% by weight of the water in the composition.
 15. The method of claim13, wherein the gas hydrate controller is from about 0.05 to about 1% byweight of the water in the composition.
 16. The method of claim 13,wherein the gas hydrate controller is from about 0.03 to about 0.75% byweight of the water present in the composition.